Directional control in most controlled-trajectory drilling is provided by two basic types of bottom hole assemblies: drilling motors and rotary assemblies. Rotary assemblies are used for maintaining the direction of a well-bore or for making minor changes in direction. Drilling motors are used for making rapid changes in direction. The positive displacement motor is a fluid-driven motor which turns the drill bit independently of drill string rotation. Examples of positive displacement motors are described in U.S. Pat. Nos. 4,059,165 and 4,679,638. The power of a positive displacement motor is generated by a power generation section that includes a rotor and stator which have helical lobes that mesh to form sealed helical cavities. When drilling fluid is pumped through the positive displacement motor, the fluid advancing through the cavities forces the rotor to rotate.
The rotor, which travels in an orbiting motion about the axis of the tool, is connected to either a flexible or articulated constant velocity coupling which transmits torque while eliminating the orbital motion. The coupling then transmits the torque to a driveshaft, which is housed in bearings to enable it to transmit both axial (i.e. "bit weight") and lateral loads from the drill string to the bit. A tandem motor may also be used which includes upper and lower power sections. Such a tandem motor is described in U.S. Pat. No. 5,620,056 issued Apr. 15, 1997, incorporated herein by reference.
A steerable motor, typically configured with a bend in the external housing and two or more stabilizers, is a positive displacement motor configured to operate as a two-mode system. In the "sliding" mode, the steerable motor is oriented by rotating the drill string, using measurement-while-drilling signals to determine toolface or bend orientation. Once the desired downhole toolface orientation is achieved, the drill string is then advanced without rotating, maintaining the desired toolface, using only the rotation generated by the positive displacement motor to drive the bit. The combination of stabilizers and bent housing generates a side load on the bit, causing it to drill in the toolface direction. Pads on the motor housing may be used instead of stabilizers. In the "rotating" mode, the entire motor is rotated, negating the effect of the bend, and its directional characteristics are determined by the size and placement of stabilizers.
FIG. 1 illustrates a simple well with a lateral borehole A. The kick-off point B is the beginning of the build section C. A build section is preferably performed at a constant build-up rate until the desired angle or end-of-build D is achieved. Build-up rate is normally expressed in terms of degrees-per-hundred-feet (deg/100'), which is simply the measured change in angle divided by the measured depth drilled.
The build section C is formed by the build-up rate of the positive displacement motor which creates lateral borehole A having a curvature with a radius. Conventional, or long radius boreholes typically are those with build-up rates between 1 and 8 degrees per 100 feet. Medium radius boreholes typically are those with build-up rates between 8 and 30 degrees per 100 feet and short radius boreholes typically are those with build-up rates over 60 degrees per 100 feet.
The build rate, or angle-changing capability of a motor, depends on the extent to which the combination of bend and stabilizers and/or pads cause the bit to be offset from the center line of a straight borehole. Increased bit offset results in higher build rate. Increased bit offset, however, results in increased side loads, as shown in FIG. 2, when kicking off or when the motor is rotated in the borehole. High bit side loads can cause damage to the gage or bearings of the bit, and limit motor life by causing driveshaft fatigue, radial bearing wear, and stator damage. Stabilizer loads and associated wear also increase.
Medium radius wells use many of the same bottom hole assembly components and well planning tools used in long radius wells. The key differences are that medium radius build rates place some limitations on the ability to rotate, and that these limitations can affect well profile. Medium radius wells may be broadly characterized by the following: the bottom hole assembly used to drill the build section cannot be rotated in that section (or at best, very limited rotation) and due to the hole curvature in the build, the component of drill pipe stress due to bending is high enough that either the stress component due to tension must be limited by well profile design or drill string rotation must be limited while in tension.
The definition of medium radius, like that of long radius, will vary with hole size. The following are approximate guidelines:
______________________________________ Hole Size Build Rate (Degrees/100') ______________________________________ 6" to 63/4" 12 to 25 81/2" 10 to 18 121/4" 8 to 14 ______________________________________
Since the motor used to drill the build section is not intended to be rotated, its configuration is somewhat different than that of a steerable motor. The stabilizers which give a steerable motor its rotating-mode directional tendencies are not needed, and in fact reduce the ability of the motor to slide, so they are typically not used. The first contact point of a medium radius bottom hole assembly is generally a pad or sleeve instead of a stabilizer, and is usually designed close to the bend to maximize the build rate capability.
Depending on hole curvature and bottom hole assembly design, it may be possible to alter the build rate while drilling in the build section without tripping for a bottom hole assembly change. As in long radius drilling, the bottom hole assembly is designed to build angle at a higher rate than necessary, then variations of steerable motor techniques are used to reduce the build rate. One method of reducing the build rate is to rotate the drill string very slowly, on the order of 1 to 10 RPM. This method is referred to as pigtailing because of the corkscrewed hole it would seem to produce. Another method, known as "rocking" or "wagging" toolface, is to orient left for some interval, then right for an equal interval. Both of these techniques can be used to make an aggressive angle-build bottom hole assembly drill a tangent-like trajectory, especially when viewed in the vertical plane. However, these practices may cause excessive stress in motor or measurement-while-drilling housings when passing through the high doglegs created.
Short radius wells may be generally characterized by the fact that hole curvature is so high that the bottom hole assembly must be articulated in order to pass through the build section. The following may be considered to define short radius:
______________________________________ Hole Size Radius (feet) Build Rate (degrees/100') Radius (feet) ______________________________________ 81/2" 48-88 120 to 65 6" to 63/4" 57-115 100 to 50 43/4" 64-143 90 to 40 33/4" 72-191 80 to 30 ______________________________________
The build rate of short radius wells is such that large diameter tubulars, such as motors or survey collars, must be articulated in order to pass through the build section. Articulations are knuckle joints or hinge points which transmit axial loads, but not bending moment. Bottom hole assembly components are shortened into lengths which will traverse through the build without interference. Without articulations, excessive bending stress and high side loads would result.
Since the articulated joints decouple bending moment from one section of the bottom hole assembly to another, the build rate of the steering section is unaffected by the stiffness or weight of the sections above it. Build rate is completely defined by the three contact points defined by the bit, the first stabilizer or pad, and the first articulation point. The overall length and offset of these components must be such that the assembly will pass through casing with a reasonable amount of force.
Bottom hole assembly modeling is used in medium radius boreholes to analyze forces on the bit and stabilizers, and bending stresses at connections and critical cross-section changes, with assemblies oriented in the model both highside and lowside. Bottom hole assembly modeling is utilized in well planning for predicting the capabilities and tendencies of each bottom hole assembly that is planned to be run. Bottom hole assembly modeling identifies the response of each bottom hole assembly to variation in operating parameters such as weight on bit, overgage or undergage hole, stabilizer wear, and formation tendencies.
Various types of directional prediction models exist, as are well known by one skilled in the art, but all are based on the principle that directional control is accomplished by applying forces to the bit that will cause the bit to drill in the desired direction. Two kinds of models are commonly used, equilibrium curvature models and "drill ahead" models. Equilibrium curvature models are static beam models which solve for the hole curvature in which all bending moments and forces on the beam are in equilibrium. A typical 2-dimensional model applies known loads (including weight-on-bit, buoyancy, and the weight of the bottom hole assembly itself) and derived loads (i.e. bit side loads due to formation anisotropy) to the bottom hole assembly components.
A gap in radius exists between the lower (in terms of build-up rate) limit of short radius and the upper limit of medium radius. This gap between medium and short radius build rates has become known as intermediate radius, typically considered to be in the range of 25 to 60 degrees per 100 feet. For a 6" to 63/4" hole size, for example, this range would be about 25 to 57 deg/100'. In the intermediate radius range, drill pipe rotation is acceptable, but conventional medium radius motors cannot achieve the necessary build rates. For conventional medium radius motors to achieve build rates in this intermediate range, extremely high bend angles have to be used. Such high bend angles produce so much bit interference with the casing that it is difficult or impossible to force the bottom hole assembly through the casing without damaging the bit. Also, at kickoff the bit side load would be so high the motor driveshaft would be in danger of breaking. If the kickoff could be initiated successfully, the bottom hole assembly tends to bind in the curve and has trouble sliding. Conventional bottom hole assemblies have other fundamental limitations in achieving a build rate for an intermediate radius well. Conventional bottom hole assemblies are relatively stiff and have a size which takes up most of the borehole. For example, a 43/4 downhole motor drills a 6 to 63/4 inch hole leaving little clearance for the bottom hole assembly. Because the bottom hole assembly is much stiffer than the drill string, the bottom hole assembly will only pass through a borehole with a maximum curvature without breaking one of its components. For a 43/4 motor, the stiffniess of the bottom hole assembly generally limits the build-up rate to 25 degrees per 100 feet to still be able to pass the bottom hole assembly and MWD collars through the curved borehole. There are also limitations on rotation in the borehole. The drill strings can be rotated through higher curvatures than can the bottom hole assemblies because the reduced diameter of the drill string causes it to be more flexible. The 31/2" drill string which is used with the 43/4" motor may be safely rotated through a build-up rate of up to 60 degrees per 100 feet.
There is a need to be able to drill intermediate radius wells without using special bottom hole assemblies. Drilling the short radius well limits the amount of drilling time and thus expense required for the borehole. However, drilling a short radius well instead of an intermediate radius well has disadvantages. In drilling a short radius well, there is the potential for the yielding of the drill string. Also, there is almost no production equipment, such as screens and liners, that can pass through and around bends greater than 60 deg/100'. This is possible in bends between 20 and 60 deg/100'. Thus, there are more production and completion options available in an intermediate radius well. Short radius wells require special drilling components. To allow bottom hole assemblies to pass through a short radius well having a build-up rate above 60 deg/100', the sections of the bottom hole assembly must be very short and articulated between the sections. The drill string cannot be rotated and is slid through the borehole. Articulated motors have also suffer from unpredictable build-up rates in this range, especially in unconsolidated formations.
Flexible members have been used with rotary drilling assemblies. U.S. Pat. No. 5,538,091 discloses a bottom hole assembly for connection to a drill string for use in directing the path of a drill bit while rotary drilling. The bottom hole assembly includes a modified cutting assembly, a stabilizer, and a flexible member interposed between the modified cutting assembly and stabilizer for drilling a predetermined portion of the hole. The modified cutting assembly may include a symmetric drill-bit assembly and a bent sub or a drill bit having cutters with a non-radially symmetric pattern. The flexible member is made of a material having a lower Young's modulus than steel and/or a member with a smaller wall thickness than the remainder of the bottom hole assembly. The flexible member may be provided by an aluminum drill collar or a composite material drill collar. Additionally, the flexible member may be an articulated member. That portion of the bottom hole assembly below the stabilizer is designed so that portion does not sag to the extent that it contacts the borehole wall when the drill string is inclined to vertical.
Further, it is known to place "compressive service" drill pipe or reduced diameter collars between the drilling assembly and drill collars to reduce stress on the drilling assembly. However, placing the flexible member above the collars relieves stress at the top of the motor but does not adequately relieve bit side loads. Placing the flexible member above the motor also does not have the desired effect of increasing build rates while preventing the motor from binding in the curved wellbore.
The bottom hole assembly of the present invention overcomes the deficiencies of the prior art.